Operators drill wells many thousands of feet in the search for hydrocarbons. The wells are expensive and take a significant amount of time to plan. To obtain hydrocarbons such as oil and gas, boreholes are drilled by rotating a drill bit attached to a drill string. The drill bit is typically mounted on the lower end of the drill string as part of a bottom-hole assembly (BHA) and is rotated by rotating the drill string at the surface and/or by actuation of down-hole motors or turbines.
Operators find it important to obtain data about the various subterranean reservoirs once the actual drilling begins. Thus, tools have been developed that gather information about the drilling equipment and or the down-hole conditions and transmit the data to the surface. A typical BHA will include a variety of sensors used to monitor various down-hole conditions—such as pressure, spatial orientation, temperature, or gamma ray count—that are encountered while drilling. A typical BHA will also include a telemetry system that processes signals from these sensors and transmits data to the surface. Engineers and geologist can then use this data in an effort to understand the formations and make plans on completion, sidetracking, abandoning, further drilling, etc.
The use of sensors during the drilling operation to provide information related to positioning or steering the drill, such as direction, orientation and drill bit information, is referred to as “Measurement While Drilling” (MWD). The phrase “Logging While Drilling” (LWD) is often used to using sensors for petrophysical or geological measurements during drilling. As used herein, “MWD” will also be used to encompass LWD applications unless otherwise specified.
An assembled BHA, which can include the drill bit, a steering assembly, a down-hole motor, a MWD/LWD sensor assembly, and a telemetry system, is typically around 100 to 150 feet in length. Also, it is not uncommon for a drilling operation to make use of modular components from different manufacturers in a single BHA. As a result, the BHA, including the sensors and telemetry system, is usually assembled at the well site. After assembly, the BHA components are typically tested to ensure they are operating correctly before the BHA is employed. Assembly and operation of the electrical components of the BHA is potentially hazardous at the well site because of the possibility of flammable gases. Testing procedures may also require heating up the system batteries to operating conditions (>130° C.) which has sometimes resulted in accidental battery explosions that have killed or injured workers at the well site. Further, there is a desire in modern drilling operations to automate as much of the drilling process as possible. Assembly and testing at the well site requires the presence of a number of workers at the site, which runs counter to the goal of automating the systems so that fewer onsite workers are required.
What is needed is an improved MWD system with a BHA that can be assembled and tested off-site and then transported to the field and that requires fewer on-site workers to install and operate the system.
The accompanying drawings are not intended to be drawn to scale. In the drawings, each identical or nearly identical component that is illustrated in various figures is represented by a like numeral. For purposes of clarity, not every component may be labeled in every drawing.